Gas condensation process

FLOW BEHAVIOR OF GAS-CONDENSATE WELLS
A DISSERTATION
SUBMITTED TO THE DEPARTMENT OF ENERGY
RESOURCES ENGINEERING
AND THE COMMITTEE ON GRADUATE STUDIES
OF STANFORD UNIVERSITY
IN PARTIAL FULFILLMENT OF THE REQUIREMENTS
FOR THE DEGREE OF
DOCTOR OF PHILOSOPHY
Chunmei Shi
March 2009

c Copyright by Chunmei Shi 2009
All Rights Reserved
ii

I certify that I have read this dissertation and that, in my opinion, it
is fully adequate in scope and quality as a dissertation for the degree
of Doctor of Philosophy.
(Roland N. Horne) Principal Adviser
(Anthony R. Kovscek)
(Franklin M. Orr, Jr.)
Approved for the University Committee on Graduate Studies.
iii

Abstract
The objective of this work was to develop a methodology to increase the productivity
of gas/condensate from gas-condensate reservoirs. Presently, gas-condensate reser-
voirs experience reductions in productivity by as much as a factor of 10 due to the
dropout of liquid close to the wellbore. The liquid dropout blocks the flow of gas
to the well and lowers the overall energy output by a very substantial degree. The
combination of condensate phase behavior and rock relative permeability results in
a composition change of the reservoir fluid, as heavier components separate into the
dropped-out liquid while the flowing gas phase becomes lighter in composition. This
effect has been sparsely recognized in the literature, although there is clear evidence
of it in field observations. This work quantified the effect, developed a scientific un-
derstanding of the phenomena, and used the results to investigate ways to enhance
the productivity by controlling the liquid composition that drops out close to the
well. By optimizing the producing pressure strategy, it should be possible to cause a
lighter liquid to be condensed in the reservoir, after which the productivity loss would
be more easily remedied. The research made use of experimental measurements of
gas-condensate flow, as well as compositional numerical simulations. Different strate-
gies have been compared, and the optimum producing sequences are suggested for
maximum condensate recovery. Results show that composition varies significantly as
a function of fluid phase behavior and producing sequence; condensate recovery can
be improved with proper producing strategy, and productivity loss can be reduced
by changing the producing sequence. This study can be used to determine the op-
timum producing strategy when the well is brought into production and reduce the
productivity loss caused by the condensate banking effect.
v

Acknowledgements
During the last six and a half years, I have been assisted by many people. Most credit
is due to my advisor, Professor Roland N. Horne, for his patience, encouragement and
guidance throughout my research. All this work would not have come to fruition had
it not been for his support.
My sincere thanks are also extended to Professor Franklin M. Orr and Professor
Anthony R. Kovscek for reading my dissertation, providing valuable comments, and
serving on my defense committee. Many thanks to Professor Jennifer Wilcox for
being a member of my examination committee.
A large portion of this work has depended on the extensive use of Gas Chromatog-
raphy from SUPRI-C laboratory and the ﬁnancial aid of SUPRI-D Aﬃliates, Saudi
Aramco and RPSEA are appreciated.
I would also like to thank Dr. Tom Tang and Qing Chen for various helpful
discussions I have had with each of them.
To my parents, Yufang Zhou and Zhenghuang Shi, for their love and support.
Especially my mother, she is such a great one. Although she did not receive any
formal education, and could not read and write, she encouraged me to leave our
small village to get better formal education. I thank my brother, ZhiYong Shi, for
taking part of my responsibility to take care of our parents while I was far away and
for making me realize other important things in life. Their unconditional support and
love have guided me through each and every step along the way.
I am especially thankful to my husband Yulin Jin who has been a colleague for
two years, and is a constant source for help and great ideas. He is always closest to
my joys and sorrows and always standing by me.
vii

Contents
Abstract v
Acknowledgements vii
1 Introduction 1
1.1 Problem Statement . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
1.2 Dissertation Outline . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
2 Concepts and Literature Review 7
2.1 Flow Behavior of Gas-Condensate Systems . . . . . . . . . . . . . . . 7
2.1.1 Constant Volume Depletion (CV D) and Constant Composition
Expansion (CCE) . . . . . . . . . . . . . . . . . . . . . . . . 8
2.1.2 Diﬀerential Condensation (DC) . . . . . . . . . . . . . . . . . 9
2.1.3 Three Flow Regions . . . . . . . . . . . . . . . . . . . . . . . . 13
2.2 Literature Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16
3 Experimental Investigation 25
3.1 Experimental Design . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.1.1 Design Principles . . . . . . . . . . . . . . . . . . . . . . . . . 25
3.1.2 Diﬀerence Between Static Values and Flowing Values . . . . . 26
3.1.3 Preexperiment Numerical Simulation . . . . . . . . . . . . . . 30
3.2 Experimental Apparatus . . . . . . . . . . . . . . . . . . . . . . . . . 37
3.2.1 Gas Supply and Exhaust . . . . . . . . . . . . . . . . . . . . . 39
3.2.2 Core Flow System . . . . . . . . . . . . . . . . . . . . . . . . 41
ix

3.2.3 Fluid Sampling System . . . . . . . . . . . . . . . . . . . . . . 41
3.2.4 Data Acquisition System . . . . . . . . . . . . . . . . . . . . . 43
3.2.5 Gas Chromatography (GC) System . . . . . . . . . . . . . . . 43
3.2.6 CT system . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
3.3 Experimental Procedures . . . . . . . . . . . . . . . . . . . . . . . . . 49
3.3.1 Gas Mixing . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
3.3.2 Core Flow Tests . . . . . . . . . . . . . . . . . . . . . . . . . . 52
3.3.3 Sampling from the Tubing Ports . . . . . . . . . . . . . . . . . 56
3.3.4 Composition Analysis . . . . . . . . . . . . . . . . . . . . . . . 57
3.3.5 X-ray Saturation analysis . . . . . . . . . . . . . . . . . . . . 59
3.4 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
4 Experimental Results 65
4.1 Experimental Results . . . . . . . . . . . . . . . . . . . . . . . . . . . 65
4.1.1 Pressure Measurements . . . . . . . . . . . . . . . . . . . . . . 65
4.1.2 Compositional Measurements . . . . . . . . . . . . . . . . . . 73
4.1.3 Saturation Measurements . . . . . . . . . . . . . . . . . . . . 80
4.1.4 Apparent Permeability Measurements . . . . . . . . . . . . . . 82
4.2 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83
5 Gas-Condensate Flow Modeling 87
5.1 Theoretical Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87
5.2 Compositional Variation Behavior . . . . . . . . . . . . . . . . . . . . 91
5.2.1 The Impact of Relative Permeability Models . . . . . . . . . . 93
5.2.2 The Impact of Pressure . . . . . . . . . . . . . . . . . . . . . . 102
5.2.3 The Impact of Fluid Types . . . . . . . . . . . . . . . . . . . . 103
5.3 Simulation Model for Binary Gas-Condensate Systems . . . . . . . . 106
5.3.1 Model Setup . . . . . . . . . . . . . . . . . . . . . . . . . . . . 106
5.3.2 Simulation Results for Binary Gas-Condensate Systems . . . . 107
5.4 Simulation Model for MultiComponent Gas-Condensate Systems . . . 109
5.4.1 Model Setup . . . . . . . . . . . . . . . . . . . . . . . . . . . . 109
5.4.2 Simulation Results for MultiComponent Gas-Condensate Systems109
x

5.5 Flow Optimization with Genetic Algorithm . . . . . . . . . . . . . . . 114
5.6 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121
6 Conclusions and Discussions 127
6.1 General Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . 127
6.1.1 Theoretical Compositional Variation Models . . . . . . . . . . 127
6.1.2 Experimental Study of Gas-Condensate Flow in a Core . . . . 128
6.1.3 Numerical Simulation Study of Gas-Condensate Flow . . . . . 129
6.2 Possible Improvements and Future Work . . . . . . . . . . . . . . . . 130
A Core Scale Simulation Input File 131
B Field Scale MultiComponent Simulation Input File 139
C Field Scale Binary Simulation Input File 149
xi

List of Tables
2.1 Four gas-condensate systems with diﬀerent compositions. . . . . . . . 17
2.2 Component composition variations for a Chinese ﬁeld. (Yuan et al.,
2003) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
3.1 Gas Chromatographic Conditions. . . . . . . . . . . . . . . . . . . . . 45
3.2 CT scanner settings. . . . . . . . . . . . . . . . . . . . . . . . . . . . 49
3.3 Parameters for CT number calculation. . . . . . . . . . . . . . . . . . 63
5.1 Fluid characterization for a multicomponent gas-condensate system. . 113
xiii

List of Figures
1.1 Phase diagram of a typical retrograde (McCain, 1990). . . . . . . . . 2
2.1 A schematic of Constant Volume Depletion (CV D) process. . . . . . 9
2.2 PT diagram and liquid drop curve for system C1/nC4 = 0.85/0.15. . . 10
2.3 A schematic of Differential Condensation (DC) process. . . . . . . . . 11
2.4 Total composition znC4 and gas composition ynC4 profiles at T = 60o
F
for system C1/nC4 = 0.85/0.15. . . . . . . . . . . . . . . . . . . . . . 11
2.5 Total composition znC4 and gas composition ynC4 profiles at T = 190o
F
for system C1/nC4 = 0.60/0.40. . . . . . . . . . . . . . . . . . . . . . 12
2.6 PT diagram and liquid dropout curve for system C1/nC4 = 0.60/0.40. 12
2.7 Heavy and intermediate components profiles at T = 190o
F for system
C1/nC4/C10 = 0.60/0.25/0.15. . . . . . . . . . . . . . . . . . . . . . . 13
2.8 PT diagram and liquid dropout curve for system C1/nC4/C10 = 0.60/0.25/0.15. 14
2.9 Schematic gas-condensate flow behavior in three regions (Roussennac,
2001). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
2.10 PT diagrams for four gas-condensate systems. . . . . . . . . . . . . . 16
2.11 Liquid dropout curves for four gas-condensate systems at T = 200o
F. 17
2.12 Vapor composition yC1 , yC4−6 , yC+2
7
and yC+3
7
for four gas-condensate
systems at T = 200o
F. . . . . . . . . . . . . . . . . . . . . . . . . . . 18
2.13 A typical production decline curve in the Whelan field (Lin and Finley,
1985). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
2.14 Profiles of component compositions for a Chinese field, (Yuan et al.,
2003). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
xv

3.1 Phase diagram for a two-component methane-butane gas-condensate
system (PVTi, 2003a, PR(1978) EoS). For this system, the critical tem-
perature and the critical pressure are Tc = 6.3 o
C and pc = 128.5 atm
respectively. At room temperature, the system produces a moderate
retrograde region. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
3.2 The difference of static values and flowing values in three regions. . . 29
3.3 Schematic of composition variation in the reservoir under different pres-
sures and at different conditions. . . . . . . . . . . . . . . . . . . . . 29
3.4 Simulation results for BHP = 70 atm scenario. (a) C4 mole frac-
tion profile in the flowing phase (b) Saturation distribution profiles at
different flow times. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
3.5 In-situ composition history of butane component in (a) Liquid phase
and (b) The overall composition configuration. . . . . . . . . . . . . . 33
3.6 In-situ composition history for butane component during buildup test
in (a) Liquid phase and (b) The overall composition configuration. . . 34
3.7 Saturation distribution in the core during buildup. . . . . . . . . . . . 35
3.8 In-situ composition history for butane component with different BHP
control scenarios in (a) Liquid phase and (b) The overall composition
configuration. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36
3.9 Simulation results for different BHP control scenarios. (a)C4 mole
fraction profiles in the flowing phase (b) Saturation distribution in the
core. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38
3.10 Schematic diagram of the gas-condensate flow system. The confin-
ing pressure is provided by a high pressure water pump and the gas-
condensate mixture is stored in a piston cylinder, which is supported
by a high pressure nitrogen cylinder to maintain the mixture pressure
at 2200psi. Pressures along the core are monitored by the high pressure
transducers and fluid samples are collected from the six ports along the
core for composition analysis. . . . . . . . . . . . . . . . . . . . . . . 39
xvi

3.11 Images of the experiment apparatus for the gas-condensate flow sys-
tem. (a) Front view, the high pressure titanium core holder is in the
foreground, this core holder has six ports along the core to allow for
pressure monitoring and fluid sampling (b) Rear view, the sampling
system and the pressure transducers are in the foreground. . . . . . . 40
3.12 Schematic and photograph of the gas sampling system. (a) Schematic
diagram. The fluid sample is first stored in the one-meter long coil,
then released to the sampling bag. (b) Photograph of the sampling
system. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
3.13 Schematic diagram of the valve and column configuration in the GC
(Parakh, 2007). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44
3.14 GC curve for a methane and butane mixture. The measurement shows
good signal-to-noise ratio, and the baseline is also very stable. . . . . 46
3.15 The calibration curve for C4 measurements. The calibrated butane
mole percentage is calculated by: zC4 c = 0.0084zC4 m2
+ 0.198zC4 m. 47
3.16 Apparatus for x-ray CT scanning. . . . . . . . . . . . . . . . . . . . . 48
3.17 Butane vapor pressure curve. . . . . . . . . . . . . . . . . . . . . . . 50
3.18 Overview of the gas mixing process. (a) Vacuum and fill the piston
cylinder with water (b) Displace water from the piston cylinder with
specified volume (c) Discharge liquid butane into the piston cylinder
(d) infill the piston cylinder with high pressure methane. . . . . . . . 53
3.19 Schematic of gas sampling directly from the cylinder with heat tape. . 57
3.20 Composition measurement with and without using the heat tape. (a)
without using heat tape (b) with heat tape. . . . . . . . . . . . . . . . 58
3.21 Butane density as a function of pressure. . . . . . . . . . . . . . . . . 62
3.22 Methane density as a function of pressure. . . . . . . . . . . . . . . . 62
3.23 Apparatus for x-ray CT scanning. . . . . . . . . . . . . . . . . . . . . 63
3.24 CT image processing. . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
4.1 Sampling pressure profiles for Experiment A. (a) Sampling without
flow (b) Sampling during flow. . . . . . . . . . . . . . . . . . . . . . . 67
xvii

4.2 Sampling pressure profiles for Experiment B. (a) Sampling during flow
(b) Sampling without flow. . . . . . . . . . . . . . . . . . . . . . . . . 68
4.3 Pressure profiles for Experiment C. (a) Flowing and sampling pres-
sure profiles (b) Build-up pressure and the static pressure in the fully
discharged core. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69
4.4 Pressure profiles for Experiment D. (a) Flowing and sampling pressures
(b) Build-up pressure and pressure in the fully discharged core. . . . . 71
4.5 Pressure profile comparison of nitrogen flow and hydrocarbon flow.
(a) Comparison of nitrogen flow run 1 and hydrocarbon Experiment
A, C and D. (b) Comparison of nitrogen flow run 2 and hydrocarbon
Experiment B. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72
4.6 Density and viscosity of nitrogen at T = 20◦
C (a) Density vs. Pressure
(b) Viscosity vs. Pressure. . . . . . . . . . . . . . . . . . . . . . . . . 74
4.7 Density and viscosity of methane and butane mixture (C1/C4 = 85%/15%)
at T = 20◦
C (a) Density vs. Pressure (b) Viscosity vs. Pressure. . . . 75
4.8 Apparent permeability ratios for nitrogen and hydrocarbon flow (ki/k1,
scaled with the apparent permeability at location 90mm.). . . . . . . 76
4.9 Butane mole percentage profiles with samples collected in Experiment
A during flow with constant pressure drop. . . . . . . . . . . . . . . . 77
4.10 Butane mole percentage profiles with samples collected in Experiment
B during flow with constant pressure drop. . . . . . . . . . . . . . . . 78
4.11 Butane mole fraction profiles with samples collected in Experiment C
immediately after the flow with constant pressure drop. . . . . . . . . 79
4.12 Butane mole fraction profiles with (a) samples collected immediately in
Experiment D after the flow with constant pressure drop (b) Samples
collected after nitrogen injection into the naturally depleted core. . . 81
4.13 Butane mole fraction in the exit flow with nitrogen injection (Experi-
ment D). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82
xviii

4.14 CT images of the core saturated with (a) liquid butane (b) gas methane
(c) the mixture of methane and butane and (d) the difference between
liquid butane and gas methane and (e) the difference between liquid
butane and the mixture of methane and butane at l = 74mm. . . . . 83
4.15 A saturation profile from CT image interpretation. . . . . . . . . . . 84
4.16 Pressure profile in the core during x-ray CT scanning. . . . . . . . . . 84
4.17 PT diagram for binary component C1/C4 = 63%/37%. . . . . . . . . 85
4.18 Apparent permeability measurements for nitrogen flow. . . . . . . . . 85
5.1 PT diagram of methane-butane systems. The reservoir temperature
is 60 o
F. At reservoir temperature, the fluid with 15% butane is a
lean gas-condensate system, the fluid with 20% butane is near critical
gas-condensate, while the fluid with 25% Butane is light oil. . . . . . 93
5.2 CVD liquid dropout curves for three fluids at temperature 60 o
F. At
reservoir temperature, the fluid with 15% butane is an lean-intermediate
gas-condensate system, having a maximum liquid drop of 10.9%; the
fluid with 20% butane is near critical gas-condensate with a maximum
liquid drop of 31.4%; the fluid with 25% Butane is light oil with 100%
oil in reservoir condition. . . . . . . . . . . . . . . . . . . . . . . . . . 94
5.3 Interfacial tension (IFT) as a function of pressure. IFT is independent
of fluid type and decreases with increasing pressure. . . . . . . . . . . 96
5.4 Different relative permeability curves for a binary methane and butane
system with 25% butane. krc(IFT) and krg(IFT) are IFT corrected
relative permeability; krci and krgi are relative permeability curves
with immiscible treatment and krcm and krgm are miscible treatment
of relative permeabilities. . . . . . . . . . . . . . . . . . . . . . . . . 97
5.5 IFT corrected relative permeability curves for binary methane and
butane systems with 15% butane, 20% butane and 25% butane. . . . 98
5.6 Variation of term Ln(mi/m) with pressure for a methane-butane sys-
tem (zC4 = 0.15) with different relative permeability models. . . . . . 99
xix

5.9 Variation of term AC4 with pressure for a methane-butane system (zC4
= 0.15) with different relative permeability models. . . . . . . . . . . 100
5.10 Variation of term AC4 with pressure for a methane-butane system (zC4
5.11 Variation of term BC4 with pressure for a methane-butane system (zC4
5.12 Variation of term BC4 with pressure for a methane-butane system (zC4
5.13 Variation of term G with pressure for a methane-butane systems with
different compositions. . . . . . . . . . . . . . . . . . . . . . . . . . . 104
5.14 Variation of term AC4 with pressure for methane-butane systems with
5.15 Variation of term BC4 with pressure for methane-butane systems with
5.16 History profiles of (a) The accumulated gas production (WGPT (b)
Well bottom hole pressure (WBHP) and (c) Gas production rate
(WGPR) for a binary gas-condensate system. . . . . . . . . . . . . . 110
5.17 Overall butane mole fraction zC4 profiles. (a) Overall butane mole
fraction BzC4 profiles in the well block vs. the well block pressure. (a)
Overall butane mole fraction WzC4 profiles in the producing fluid vs.
BHP. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111
5.18 Overall butane mole fraction zC4 history profiles. (a) History of the
overall butane mole fraction BzC4 in the well block. (a) History of the
overall butane mole fraction WzC4 profiles in the producing fluid. . . 112
(WGPR for a multicomponent gas-condensate system. . . . . . . . . 115
xx

5.20 Overall butane mole fraction zC+
7
profiles. (a) Overall butane mole
fraction BzC+
7
profiles in the well block vs. the well block pressure. (a)
Overall butane mole fraction WzC+
7
profiles in the producing fluid vs.
BHP. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116
5.21 Overall butane mole fraction zC+
7
history profiles. (a) History of the
overall butane mole fraction BzC+
7
in the well block. (a) History of the
overall butane mole fraction WzC+
7
profiles in the producing fluid. . . 117
5.22 Computation procedure for Genetic Algorithm. . . . . . . . . . . . . 118
(WGPR for the top three WBHP GA optimized scenarios. . . . . . 120
BHP for the top three WBHP GA optimized scenarios. . . . . . . . 121
overall butane mole fraction WzC4 profiles in the producing fluid for
the top three WBHP GA optimized scenarios. . . . . . . . . . . . . . 122
(WGPR for the top three WGPR GA optimized scenarios. . . . . . . 123
BHP for the top three WGPR GA optimized scenarios. . . . . . . . 124
overall butane mole fraction WzC4 profiles in the producing fluid for
the top three WGPR GA optimized scenarios. . . . . . . . . . . . . . 125
xxi

Chapter 1
Introduction
Gas-condensate reservoirs represent an important source of hydrocarbon reserves and
have long been recognized as a reservoir type, possessing the most intricate flow and
complex thermodynamic behaviors. Gas-condensate reservoirs are characterized by
producing both gas and condensate liquid at surface. Typical retrograde condensate
reservoirs produce gas/liquid ratios of approximately 3-150 MCF/STB (McCain,
1990), or condensate surface yields ranging from 7 to 333 STB/MMCF. The added
economic value of produced condensate liquid, in addition to gas production, makes
the recovery of condensate a key consideration in the development of gas-condensate
reservoirs.
The phase diagram of a gas-condensate system has a critical temperature less than
the reservoir temperature and a cricondentherm greater than the reservoir temper-
ature (see Figure 1.1). The gas-condensate reservoir is initially gas at the reservoir
condition, point 1, and as the reservoir pressure decreases below the dewpoint, point
2, liquid condenses from gas and forms a “ring” or “bank” around the producing well
in the near-well region. Normally this liquid will not flow until the accumulated con-
densate saturation exceeds the critical condensate saturation (Scc) due to the relative
permeability and capillary pressure effects in the porous medium. Once the reservoir
pressure drops below the dewpoint, a pressure-drop occurs during production which
tends to form condensate banking (also known as the condensate blockage effect)
around the well. This causes a loss in productivity. As the reservoir pressure further
1

2 CHAPTER 1. INTRODUCTION
Figure 1.1: Phase diagram of a typical retrograde (McCain, 1990).
draws down to lower pressure, point 3, the liquid begins to revaporize in a PVT cell
experiment. However, the revaporization may not take place in the reservoir because
the overall composition of the reservoir fluid changed during production. As a conse-
quence of the composition variation, the total concentration of the heavy component
in the reservoir fluid will be higher than that of the original reservoir fluid. This leads
to the recovery problem associated with the heavier components, which are usually
not easy to recover once stuck in the reservoir.
Condensate blockage near the well may cause a significant loss in well productiv-
ity for low-to-moderate permeability high-yield condensate reservoirs since the main
source for pressure loss in the tight reservoir depends primarily on reservoir perme-
ability. Several other factors, including initial productivity, amount of near wellbore
liquid saturation due to condensation, phase behavior of well block fluid and how the
well is being produced (different producing pressure schemes) appear to influence the
observed level of productivity decline. A better understanding of how the condensate
accumulation influences the productivity and the composition configuration in the

1.1. PROBLEM STATEMENT 3
liquid phase is very important to optimize the producing strategy for gas-condensate
reservoirs, to reduce the impact of condensate banking, and to improve the ultimate
gas and condensate recovery.
1.1 Problem Statement
This research studied the well deliverability (productivity) issue associated with con-
densate blockage effect with an emphasis on flow behavior analysis. Although exten-
sive research and development have been performed in this general area, there still
exist many important and outstanding issues. Specifically, this work focused on the
following aspects:
• Composition variation. The objective of this work was to study how the com-
positions of heavy components of a gas condensate system change with time
around production wells during depletion, and how the rate of the composition
variation influences the fluid thermodynamic properties, and hence, defines the
dynamic phase diagram of the fluid in the reservoir. It should be noted that
the extent or even the existence of compositional changes has been noted in the
literature rather infrequently, which is an indication that the importance of this
phenomenon has not been fully recognized.
• Dynamic condensate saturation build-up. Due to compositional variation and
relative permeability constraints, the condensate saturation build-up is a dy-
namic process and varies as a function of time, place (distance to wellbore) and
phase behavior. In this work, we conducted CT experiments to investigate how
the liquid accumulates and distributes in a core.
• Producing schemes. Different producing strategies may impact the composition
configuration for both flowing and static phases and the amount of the liquid
trapped in the reservoir, which in turn may influence the well productivity and
hence the ultimate gas and liquid recovery from the reservoir. Changing the
manner in which the well is brought into flowing condition can affect the liquid

4 CHAPTER 1. INTRODUCTION
dropout composition and can therefore change the degree of productivity loss.
In this study, we conducted parametric studies to identify the most influential
reservoir and fluid characteristics in the establishment of optimum gas produc-
tion and condensate recovery for the exploitation of gas-condensate reservoirs.
1.2 Dissertation Outline
This dissertation proceeds as follows. Chapter 2 presents a literature review on con-
densate blockage effect around the well and the associated impairment in gas produc-
tivity and condensate recovery. The chapter includes advantages and limitations of
existing techniques and some outstanding issues are discussed.
Chapter 3 describes a core flooding experiment with two-component synthetic gas-
condensate, designed and constructed to model gas-condensate production behavior
from pressure above the dew-point to below. This experimental equipment was con-
structed to allow detailed and accurate measurements of real time pressure and in
situ composition of the flowing fluid along the core.
Experimental observations are discussed in Chapter 4. Five example experiments
on the binary gas-condensate system demonstrate and confirm the compositional
variation in the gas-condensate flow, even in the constant pressure-drop flow case.
In the first part of Chapter 5, a general form of material balance equation for con-
densate flow in porous media was developed for both one-dimensional linear flow and
three-dimensional radial flow of two-phase gas-condensate fluid through porous me-
dia, with the effect of interfacial tension. The compositional variation of the reservoir
fluid, especially the heavier component of the fluid, around the well during conden-
sate dropout was analyzed. Key parameters that influence the compositional be-
havior were also discussed in detail. The theoretical models provide tools to better
understand the momentary compositional variation in the reservoir. In the second
part of this chapter, compositional simulations of binary-component and multicom-
ponent gas-condensate fluids were designed and conducted at field scale to investigate
the composition and condensate saturation variations. Different producing strategies

1.2. DISSERTATION OUTLINE 5
were tested to fathom the optimum producing sequences for maximum gas and con-
densate recovery. By taking into account the new understanding of the impact of
compositional changes, the composition of the liquid dropout can be “controlled” by
the production strategy (for example by dropping a lighter liquid in preference to
a heavier one). Hence the recovery from gas reservoirs, especially tight ones, with
condensate ﬂuids can be improved.
Chapter 6 summarizes the results of this work and provides some insight into
possible future research in experimental study for gas-condensate ﬂow.

Chapter 2
Concepts and Literature Review
The flow behavior of a gas-condensate system depends on both the phase envelope of
the fluid and the conditions of the reservoir (such as pressure, temperature and rock
properties etc.). Due to compositional variation and relative permeability constraints,
the build-up of condensate saturation around the well is a dynamic process and varies
as a function of time, place (distance to wellbore) and phase behavior. In this chapter,
we explore several key concepts about the flow behavior of the gas-condensate system
and define the prospective issues for this study. Previous research on these issues will
be reviewed.
2.1 Flow Behavior of Gas-Condensate Systems
To analyze the flow behavior of a gas-condensate system, we first need to understand
the difference between the values of static and flowing properties. The static values
are for in-situ fluid properties defined at a specific reservoir location at a given time,
while the flowing values are associated with the properties of the flowing fluids. In
reservoir simulations static values will refer to the property values of a given grid block
at a given time, while in laboratory experiments and field sampling cases, the sample
collected at the wellhead only comes from the flowing phase. Hence, compositions of
the wellhead samples will not be the same as the overall compositions in the reservoir
or the static values in reservoir simulations, although they can indicate the changes
7

8 CHAPTER 2. CONCEPTS AND LITERATURE REVIEW
of flow property variations in the reservoir.
2.1.1 Constant Volume Depletion (CV D) and Constant Com-
position Expansion (CCE)
Gas-condensate fluid is investigated primarily using Constant Composition (Mass)
Expansion (CCE/CME) to obtain the dewpoint and Constant Volume Depletion
(CV D) to simulate reservoir production behavior. CCE is also called flash vapor-
ization and is simulated by expansion of a mixture with a fixed composition (zi) in
a series of pressure steps. During the CCE experiment, no gas or liquid is removed
from the cell, and at each step, the pressure and total volume of the reservoir fluid (oil
and gas) are measured. As the name CCE implies, the reservoir fluid composition
does not change during the production process. However,in a reservoir the heavier
component drops out to the reservoir during production as condensation develops in
the reservoir and this will definitely alter the configuration of the fluid composition
in the reservoir.
In the CV D procedure (as shown in Figure 2.1), the sample of reservoir liquid in
the laboratory cell is brought to the dewpoint pressure, and the temperature is set
to the reservoir temperature. Pressure is reduced by increasing the cell volume. Part
of the gas is expelled from the cell until the volume of the cell equals the volume
at the dewpoint. The process is repeated for several pressure steps and the liquid
volume at each pressure(V L
T ) is recorded and liquid dropout(V L
T /V dew
T ) is calculated.
The CV D experiment is a good representation of the reservoir depletion only if the
condensate phase is totally immobile, which is not true if condensate saturation ex-
ceeds the critical condensate saturation (SCC) and part of the condensate can flow
in the porous medium. At the same time, the liquid dropout estimation from the
CV D experiment does not account for the condensate buildup in the reservoir; hence
it cannot indicate the maximum possible condensate accumulation in the reservoir.
Taking a binary system C1/C4 for example, the maximum liquid dropout is less than
10% from the CV D experiment (Figure 2.2), however, reservoir simulation shows
that the condensate saturation can be as high as 57.5%, as will be discussed in more

2.1. FLOW BEHAVIOR OF GAS-CONDENSATE SYSTEMS 9
Figure 2.1: A schematic of Constant Volume Depletion (CV D) process.
detail in Chapter 3.
2.1.2 Differential Condensation (DC)
Heavier components separate into the dropped-out liquid while the flowing gas phase
becomes lighter in composition. By checking the wellhead fluid sample, we can in-
vestigate how the composition change with time. Differential Condensation (DC) is
a procedure assumed in this study to investigate the composition variation at the
wellhead. In the DC experiment (as shown in Figure 2.3), the sample of reservoir gas
in the laboratory cell is first brought to the dewpoint pressure, and the temperature
is set to the reservoir temperature. Next, pressure is reduced by increasing the cell
volume. Then all the liquid is expelled from the cell while pressure is held constant by
reducing the cell volume. The process is repeated in steps until atmospheric pressure
is reached. Liquid and vapor compositions are analyzed at each pressure step. In this
procedure no condensate is mobile during production, which may underestimate the
heavy component recovery at the surface since in reality part of the condensate phase
can flow once the accumulated condensate saturation exceeds the critical condensate

Figure 2.2: PT diagram and liquid drop curve for system C1/nC4 = 0.85/0.15.
saturation. However, this experiment can tell us how much of the heavier component
would be trapped in the reservoir in the worst case. Different from CCE (or flash
vaporization), the overall fluid composition in the DC procedure varies as we keep
removing the liquid phase from the mixture.
Comparing the regular flash vaporization and the DC procedure (Figure 2.4), in
the example fluid 0.85 C1 and 0.15 C4 we can find that as much as 7.6% (over 15%
original) of the heavy component butane can fail to reach the surface if no condensate
is brought to flow. Similarly, also about 6.4% (over 40% original) butane (Figure 2.5)
can be lost from a richer gas-condensate system C1/nC4 = 0.60/0.40 (Figure 2.6).
The extent of heavy component lost seems less severe in the rich gas-condensate case
in this example.
Figure 2.7 shows the comparison of the DC and flash results for a rich three-
component gas-condensate system, with the PT diagram and liquid drop-out curve
shown in Figure 2.8. Similar to the simple binary system, both heavy component
decane and intermediate component butane are lost to production in the DC proce-
dure. In terms of liquid dropout, the richer three-component system C1/nC4/C10 =
0.60/0.25/0.15 has the least heavy component loss given no condensate flow in the

Figure 2.3: A schematic of Diﬀerential Condensation (DC) process.
Figure 2.4: Total composition znC4 and gas composition ynC4 proﬁles at T = 60o
F for
system C1/nC4 = 0.85/0.15.

Figure 2.5: Total composition znC4 and gas composition ynC4 proﬁles at T = 190o
F
for system C1/nC4 = 0.60/0.40.
Figure 2.6: PT diagram and liquid dropout curve for system C1/nC4 = 0.60/0.40.

Figure 2.7: Heavy and intermediate components profiles at T = 190o
F for system
C1/nC4/C10 = 0.60/0.25/0.15.
reservoir.
2.1.3 Three Flow Regions
According to Fevang (1995), fluids flowing toward a producing well in a gas-condensate
reservoir during depletion can be divided into three main flow regions, as shown in
Figure 2.9:
• Single-phase gas region 3: A region that is far away from the well and has
reservoir pressure higher than the dewpoint, and hence only contains single-
phase gas.
• Condensate buildup region 2: A region where reservoir pressure drops below the

Figure 2.8: PT diagram and liquid dropout curve for system C1/nC4/C10 =
0.60/0.25/0.15.
Figure 2.9: Schematic gas-condensate ﬂow behavior in three regions (Roussennac,
2001).

dewpoint, and condensate drops out in the reservoir. However, the accumulated
condensate saturation is not high enough for the liquid phase to flow. Therefore,
the flowing phase in this region still contains only the single gas phase, and the
flowing gas becomes leaner as the heavier component drops into the reservoir.
• Near well region 1: An inner near-well region where reservoir pressure drops
further below the dewpoint, the critical condensate saturation is exceeded, and
part of the condensate buildup becomes mobile. The mobility of the gas phase
is greatly impaired due to the existence of the liquid phase.
Both the CV D and DC procedures assume that the accumulated condensate is
totally immobile in the reservoir. However, as we can infer from Figure 2.9, the con-
densate buildup in region 1 can flow if the accumulated condensate in this region is
sufficient to overcome the relative permeability constraint (immobile liquid satura-
tion). The liquid-phase flow alleviates the heavy component loss at the surface to
some extent, but because of the coexistence of gas and liquid phases, the gas mobility
is greatly impaired. The composition of reservoir fluid becomes complex as part of the
liquid participates in the flow. Figure 2.10 shows four different composition scenarios
in a reservoir as reservoir pressure drops below dewpoint. Compositions 1, 2, 3 and
4 (Table 2.1) correspond to reservoir pressures p1, p2, p3 and p4 respectively. As the
reservoir pressure drops, the PT diagram changes significantly from a relatively lean
gas-condensate system (Composition 1), to a richer system (Composition 2) and then
finally to a volatile oil system (Composition 3). The CV D experiment estimation
(Figure 2.11) shows a great increase of the liquid volume percentage as the reservoir
depletes. Figure 2.12 shows the vapor phase composition profile for light component
C1, intermediate component C4−6 and heavy component C+2
7 and C+3
7 for scenarios of
different fluid configurations in the reservoir. Note that although there are dramatic
changes in the PT diagram, the heavy components C+2
7 and C+3
7 in the vapor phase
vary little as the reservoir pressure drops below 2200 psi.

Figure 2.10: PT diagrams for four gas-condensate systems.
2.2 Literature Review
In this section, we review previous work on the issue of condensate buildup, since it is
the primary factor causing the decrease in the relative permeabilities and thus reduc-
ing the well-deliverability in gas-condensate reservoirs. Factors controlling condensate
blockage can be classiﬁed in diﬀerent ways. As will be discussed later, among many
contributing parameters, the phase behavior, the relative permeability and the well
producing scheme are three of the most important aspects for both understanding the
dynamic condensate banking and developing the optimum strategies for the recovery
of both gas and condensate. We therefore present this literature review primarily
based on these three factors.

2.2. LITERATURE REVIEW 17
Table 2.1: Four gas-condensate systems with diﬀerent compositions.
Component Composition 1 Composition 2 Composition 3 Composition 4
N2 1.210 1.174 1.103 0.977
CO2 1.940 1.752 1.558 1.438
C1 65.990 61.577 56.161 50.645
C2 8.690 8.694 8.511 7.598
C3 5.910 6.217 6.534 6.130
C4−6 9.670 11.228 13.385 14.804
C+1
7 4.745 6.306 8.628 12.370
C+2
7 1.515 2.588 3.556 5.339
C+3
7 0.330 0.463 0.565 0.698
Figure 2.11: Liquid dropout curves for four gas-condensate systems at T = 200o
F.

Figure 2.12: Vapor composition yC1 , yC4−6 , yC+2
7
and yC+3
7
for four gas-condensate
systems at T = 200o
F.
The eﬀect of condensate blocking on well productivity is a broad and active re-
search area that has attracted many researchers, including Fussell (1973), Hinchman
and Barree (1985), Aziz (1985), Clark (1985) and Vo et al. (1989). The productiv-
ity loss caused by condensate buildup is striking. According to Whitson (2005), in
some cases, the decline can be as high as a factor of 30. Several examples of severe
productivity decline are available in the literature such as Engineer (1985), Duggan
(1972), Allen and Roe (1950), Abel et al. (1970) and Aﬁdick et al. (1994) etc. Even in
very lean gas-condensate reservoirs with a maximum liquid dropout of only 1%, the

Figure 2.13: A typical production decline curve in the Whelan field (Lin and Finley,
1985).
productivity may be reduced by a factor of about two as the pressure drops below the
dewpoint pressure (Fevang and Whitson, 1996). Barnum et al. (1995) reviewed data
from 17 fields, conducted a survey on field examples from Exxon and other published
industrial cases, and concluded that a severe drop in gas recovery occurs primarily in
low productivity reservoirs with a permeability-thickness below 1000 md − ft. In a
tight gas reservoir, Figure 2.13 shows the typical production decline line curve in the
Whelan field (Lin and Finley, 1985), which has an average permeability of 0.153md
and 70 percent of the producing wells have permeabilities less than 0.1md. The gas
productivity of this tight gas field is reduced by a factor of about 10. In contrast,
there are no reported examples of severe decline from high productivity formations.
Similarly, most wells producing from gas caps below the saturation pressures do not
experience significant declines, perhaps because of the relatively low liquid content of
the gas in most associated gas caps.
It has been recognized in the literature that the relative permeability does impact
the degree of productivity loss below the dewpoint. Hinchman and Barree (1985)

showed how the choice between the imbibition and the drainage relative permeabil-
ity curves used in the numerical reservoir simulations could dramatically alter the
productivity forecast for gas-condensate reservoirs below the dewpoint pressure.
Fevang and Whitson (1996) addressed the well deliverability problem in their
gas-condensate modeling, in which they observed that the impairment of the well
deliverability resulting from the near well-bore condensate blockage effect depends
on the phase behavior, absolute and relative permeabilities, and how the well is
being produced. According to Fevang and Whitson (1996), the well deliverability
impairment resulting from the near well-bore condensate blockage depends on the
relative permeability, especially for gas and oil relative permeability ratios (krg/kro)
ranging from 0.05 to 0.3. In their well deliverability calculations, Fevang and Whitson
(1996) approximated the condensate saturation in Region 2 with the liquid dropout
curve from a CV D experiment. This approximation, however, did not account for
the condensate accumulation and the variations of the overall compositions in the
reservoir caused by the liquid build-up, hence it can not accurately estimate the well
deliverability for the condensate blockage effect.
Unfortunately, at this time we do not have a demonstrated capability in the indus-
try to measure the relative permeabilities at reservoir conditions for gas-condensate
systems. Most of the available work has concentrated on the measurement of the
endpoints of the relative permeability curves. A variety of laboratory work is still
underway in both academia and the industry to try to understand the nature of the
relative permeability relationships for gas-condensate systems.
Variations of the fluid flow properties at the time of discovery have also been ob-
served and discussed for many reservoirs around the world (examples include Riemens
and de Jong (1985) for Middle Eastern reservoirs and Schulte (1980) for North Sea
reservoirs). Lee (1989) also presented an example to show the variation of the com-
position and the saturation of a gas-condensate system due to the influences of the
capillary and gravitational forces. The composition change has also been observed in
the field (Yuan et al., 2003). Table 2.2 shows fluid samples for Well K401 and Well
K233, from the Kekeya gas field in China. These two wells are from the same reser-
voir and close in location. Three fluid samples were collected in this reservoir: one

Table 2.2: Component composition variations for a Chinese field. (Yuan et al., 2003)
Compononent Well K401 @ initial Well K233(mol%) Well K233(mol%)
reservoir condition (mol%) Year 1995 Year 1999
C1 + N2 77.280 83.86 86.08
C2 7.935 7.78 9.30
C3 3.126 2.38 2.60
C4 2.505 1.52 0.65
C5+ 8.909 4.40 1.31
from well K401, showing the initial reservoir condition, and the other two from Well
K233, collected four years apart. We can see clearly that as the reservoir pressure
drops, the produced fluid become leaner and leaner. Two other observations from the
same field are shown in Figure 2.14. Before the gas cycling, the fluid samples from
both wells grow leaner in heavy components. Furthermore, because the flowing fluid
becomes lighter, the liquid trapped in the reservoir ends up being richer in the heavy
components and therefore the blockage is more difficult to remedy because it will not
revaporize.
Roussennac (2001) illustrated the compositional change during the depletion in
his numerical simulation. According to Roussennac (2001), during the drawdown
period, the overall mixture close to the well becomes richer in heavy components as
the liquid builds up in the well grid cell, and the fluid behavior changes from the
initial gas-condensate reservoir to that of a volatile/black oil reservoir.
To characterize the condensate banking dynamics, Wheaton and Zhang (2000)
presented a general theoretical model to show how the compositions of the heavy
components in a gas-condensate system change with time around the production
wells during depletion. According to Wheaton and Zhang’s model, the rate of change
in heavy component composition is higher for a rich gas-condensate system than for
a lean gas-condensate system for the same reservoir, and the condensate banking
problem is particularly acute for low-permeability high-yield condensate systems.

Figure 2.14: Profiles of component compositions for a Chinese field, (Yuan et al.,
2003).
Bengherbia and Tiab (2002) also demonstrated in their study that both the pro-
duction history and the simulation prediction show an increase in lighter components
in the flowing phase once the pressure drops below the dewpoint, but it is still not
clear how the compositions vary with time and space and how the composition change
affects the gas production and the condensate recovery.
The well producing scheme may impose significant impacts on the phase behavior.
However, the manner by which the producing scheme influences the phase behavior
has not yet been sufficiently addressed. Recently, the work of Ayala et al. (2007)
shows major progress in tackling problems related to the production optimization.
Ayala et al. (2007) conducted parametric studies with the neurosimulation technique
to identify the most influential reservoir and fluid characteristics in the establishment
of the optimum production strategies for a gas-condensate system. Eight different
input variables investigated in their study were: permeability, porosity, drainage area,
thickness, pressure ratio of pwf /pi, bottomhole pressure, initial drawdown and initial

reservoir pressure. The advantage of the artificial-neural-network (ANN) is that it
provides a screening tool for a variety of gas-condensate reservoirs. With the aid
of such a tool, the engineer would be able to evaluate the viability of profitable
production without resorting to costly full-scale simulations. In addition, once the
possibility of the profitable production has been confirmed, the expert system could
be used to establish the best production scheme to be implemented for the field
development.
Other parameters, such as the relative permeability and the phase behavior, are
also key to the production strategy and have not yet been investigated so far; hence
they need to be addressed in future parametric studies. In spite of the numerous
methods proposed for measuring the relative permeability, investigating the phase
behavior and optimizing the condensate recovery for gas-condensate systems, there
is still no completely general approach for phase behavior analysis, especially for
the effect of compositional variations on gas-condensate systems. The flowing phase
behavior is influenced directly by the relative permeability and defines the conden-
sate recovery schemes of gas-condensate systems. Accordingly, this work focused on
flowing phase behavior and the impact of flowing composition changes.

Chapter 3
Experimental Investigation
In this chapter, we present our work on the experimental study of a synthetic binary
gas-condensate flow in a Berea sandstone core. The core-flooding experiment is di-
rectly analogous to the flow in a reservoir. The compositional behavior during the
core flow and the factors that influencing the compositional distribution are studied
and discussed.
It is important to keep in mind that the experiment has been designed to simulate
reservoir conditions using a synthetic gas-condensate fluid. Gas-condensate fluids
from real reservoirs are much more complicated than the binary fluids used here,
so the analogy here is only a simplified one. However, the apparatus is useful for
indicating compositional features of a gas-condensate flow in porous media.
3.1 Experimental Design
3.1.1 Design Principles
To investigate the composition change resulting from condensation due to the pressure
variation and the condensate hold-up due to relative permeability effect, we needed to
select an appropriate gas-condensate mixture to conduct the core flooding experiment.
In this study, we chose a binary component gas-condensate mixture based on the
following principles:
25

26 CHAPTER 3. EXPERIMENTAL INVESTIGATION
• The mixture should be easy to handle in the laboratory, thus two to four com-
ponents are preferred;
• The critical temperature of the mixture should be below 20 o
C, which makes
the experiment easy to perform at room temperature, and the critical pressure
should be relatively low, so it can be conducted within a safe pressure range;
• A broad condensate region is desirable in order to achieve considerable conden-
sate dropout during the experiment;
• Gas and liquid should show large discrepancies in density so as to be easily
distinguished by X-ray CT imaging.
Figure 3.1 shows the phase envelope for a binary gas-condensate mixture which
satisfies the four principles mentioned above. This system is composed of a mix of
85% methane and 15% butane. At a temperature of 20 o
C and a pressure from 130
atm to 70 atm, this phase diagram has a good retrograde region.
3.1.2 Difference Between Static Values and Flowing Values
Numerical simulation models can provide relatively fast and inexpensive estimates
of the performance of alternative system configurations and/or alternative operating
procedures. Hence, some preliminary numerical simulations were performed prior to
the experiment to investigate possible operating schemes. To use the simulation re-
sults properly, it is important to understand the difference between simulation and
experiment outputs, especially the static and flowing parameter values in each set-
ting. The static values are properties, such as saturation and compositions of each
component, at a given reservoir location, while the flowing values are only associated
with the property of the flowing fluid at this given location and a given time. In the
reservoir simulation, static values will refer to the property values of a given grid block
at a given time, while in experiment and field cases, samples collected come from the
flowing phase only. Due to the constraints of relative permeability and interfacial
tension, only the gas and some part of the liquid is mobile, hence the component

3.1. EXPERIMENTAL DESIGN 27
Figure 3.1: Phase diagram for a two-component methane-butane gas-condensate sys-
tem (PVTi, 2003a, PR(1978) EoS). For this system, the critical temperature and
the critical pressure are Tc = 6.3 o
C and pc = 128.5 atm respectively. At room
temperature, the system produces a moderate retrograde region.
composition of the flowing phase is generally different from the static values in the
two-phase region. The discrepancy between the static values and flowing values de-
pends on the flow region, as shown in Figure 3.2. In Region1, the flow pressure is
still above the dewpoint pressure, only the single-phase gas flow is present, hence the
static values and flowing values in Region1 will be the same. In Region2, the flow
pressure drops below the dewpoint pressure, liquid forms, drops out from the gas
phase and accumulates in the reservoir. However, the accumulated liquid saturation
is not sufficient to overcome the constraint of relative permeability, the liquid remains
immobile. Thus unlike Region1, the property values in the flowing phase in this re-
gion will differ from the static values. In Region3, the accumulated liquid saturation
exceeds the critical liquid saturation, part of the liquid starts to join the flowing gas
phase and would be produced at the wellhead (Figure 3.3). Thus in Region3, the

static and flowing phase fluid properties will differ. In the simulation, the overall
hydrocarbon component mole fractions at the separator are calculated based on the
mass balance, as given by Eq. 3.1, then a flash calculation is performed at separator
condition and fixed zc to determine the hydrocarbon component mole fraction in the
liquid phase (xc) and in the vapor phase (yc) respectively.
zc =
QWH
c /Mwc
nh
i=1
QWH
i /Mwi
(3.1)
Mwc is the component molecular weight, and QWH
c is the component well head mass
flow rate, is calculated as Eq. 3.2:
QWH
i = WIWH
·
p
λpρpXip(pp − pWH
) (3.2)
WIWH
is the well index (Peaceman, 1996), a constant defined by the geometry
property of the well blocks; pp is the phase pressure of the well block and pWH
is the
wellbore pressure for the well in the well block; Xcp is the mole fraction of component
c in phase p; λp is mobility of phase p, and ρp is the density of phase p. The phase
mobility is determined by Eq. 3.3:
λp =
krp
µp
(3.3)
Because of the liquid build-up around the well and in the reservoir, the overall
component mole fractions (the static values) at a given location and a given time
also changes with time, and can be very different from the original reservoir fluid
configuration. The overall hydrocarbon component mole fractions in the reservoir is
given by Eq. 3.4 in two-phase scenario:
zc = xcL + ycV (3.4)
or Eq. 3.5 given the saturation and component molar density information known.

Gas
Oil
Flowing
phase
Static
phase
Region 1 Region 2 Region 3
Wellbore
Distance from the well
Flow direction
Figure 3.2: The difference of static values and flowing values in three regions.
Figure 3.3: Schematic of composition variation in the reservoir under different pres-
sures and at different conditions.

zc = xcSlρl + ycSgρg (3.5)
Where, L and V are liquid and vapor mole fraction respectively, Sl and Sg are
the liquid and gas phase saturation respectively and ρl and ρg, the component molar
density of liquid and gas phase respectively.
3.1.3 Preexperiment Numerical Simulation
In this study, several preexperiment numerical simulations at core scale were con-
ducted to define the experimental parameters, such as flow pressures and experiment
duration, and to examine the range of the liquid buildup and the extent of the com-
positional variation. Two wells, one gas injector and one producer, were used in these
simulation models. Both wells were controlled by bottom-hole pressures (BHP).
The BHP of the upstream injector was set above the reservoir dewpoint pressure
while the downstream producer has BHP below the dewpoint pressure, such that
the fluid from the injection well was always in gas phase, and the fluid around the
producing well was always in two-phase. The flow in the core flooding simulation was
manipulated under the condition of constant pressure drop.
To investigate the experimental duration, we first set the BHP control for injector
at 130 atm and for producer at 70 atm, thus a constant pressure drop of 60 atm is
maintained. Figure 3.4 (a) illustrates that in the preexperimental simulation the
mole fraction of the heavier component C4 in the flowing phase drops to about 8%
and then within one minute it stabilizes to the upstream C4 composition of 15% as
the flow reaches steady-state; meanwhile, liquid saturation (Figure 3.4 (b)) builds
up quickly once the pressure drops below the dewpoint pressure and the maximum
condensate accumulation reaches as high as 53% in one minute, although the critical
condensate saturation (Scc) is only 25% based on the input relative permeability
curve and the maximum liquid dropout from the CV D experiment is only 9%. A
wide range of saturation change occurs within one minute, and after two minutes, the
saturation has a slight drop from the maximum value and stabilizes around 52% near
the producer region. The saturation around the injector remains zero as two phases

do not develop in regions with high reservoir pressure.
The composition of butane component in the liquid phase (Figure 3.5 (a)) and the
overall in-situ composition of butane component (Figure 3.5 (b)) also show dramatic
changes within the first two minutes of flow. Due to the relative permeability effect,
the liquid dropout accumulates in the reservoir, and causes a major change in the
in-situ composition configuration. The overall butane composition changed from the
original 15% to 45% around the producer.
Composition varies little in the flowing phase under constant pressure control, as
we just illustrated. Only the flowing phase can be collected in the lab/field through
the producing fluid, so in addition to the fluid sampled during the constant pressure
drop flow, we needed to develop a methodology by which we can collect samples to
investigate the composition variation that occurred in the reservoir. In the simulation,
both the injector and the producer are open, and the flow is maintained under constant
pressure drop, then after 60 minutes both wells are shut down. Figure 3.6 shows
profiles for both xC4 and zC4 history before and after the buildup test. From the
simulation results, we can conclude that both the static overall butane mole fraction
(zC4 ) and the liquid butane composition xi vary immediately after the shutdown of
injector and producer. The greatest variation of component mole fraction occurs
within six seconds after the shutdown and around the producer. After six seconds,
the composition profiles stabilize as depicted the curves at t = 60.0997 minutes in
Figure 3.6. The saturation profiles (Figure 3.7) also show dramatic changes before
and after the shutdown. Different from the saturation profiles, the composition profile
keeps changing after t = 60.0997 minutes as the saturation dispersion proceeds in the
core.
Besides the buildup test, we also looked into the behavior of flow under different
bottom hole pressure (BHP) controls. These simulations were performed with the
same BHP control on the upstream injector (BHP = 130 atm), but different BHP
controls on the downstream producer. The downstream BHP ranged from 30 atm
to 110 atm, which gives a range of pressure drop from 100 atm to 20 atm. Figure 3.8
shows that the lower the bottom-hole pressure (BHP), the more the butane accu-
mulates in both liquid phase and the heavier the overall composition configuration.

10
−1
10
0
10
1
10
2
10
3
0
0.05
0.1
0.15
0.2
0.25
Time (minutes)
FlowingzC4
molefractioninthewellgridblock BHP = 70 atm
(a) C4 mole percentage in the flowing phase.
0 5 10 15 20 25 30
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
Distance to the well (cm)
Liquidsaturation(S
c
,fraction)
t = 0.10002 minutes
t = 0.49998 minutes
t = 1 minutes
t = 2 minutes
t = 5 minutes
(b) Saturation distribution profiles.
Figure 3.4: Simulation results for BHP = 70 atm scenario. (a) C4 mole fraction
profile in the flowing phase (b) Saturation distribution profiles at different flow times.

0 5 10 15 20 25 30
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
xC4
(liquidC4
inthegridblock)
t = 0.10002 minutes
t = 0.49998 minutes
t = 1 minutes
t = 2 minutes
t = 5 minutes
t
(a) xC4 distribution.
0 5 10 15 20 25 30
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
ZC4
(overallC4
inthegridblock)
t = 0.10002 minutes
t = 0.49998 minutes
t = 1 minutes
t = 2 minutes
t = 5 minutes
t
(b) zC4 distribution.
Figure 3.5: In-situ composition history of butane component in (a) Liquid phase and
(b) The overall composition conﬁguration.

0 5 10 15 20 25 30
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
xC4
(liquidC4
inthegridblock) t = 60 minutes
t = 60.0166 minutes
t = 60.0997 minutes
t = 120.9972 minutes
t
0 5 10 15 20 25 30
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
ZC4
(overallC4
inthegridblock)
t = 60 minutes
t = 60.0166 minutes
t = 60.0997 minutes
t
(b) zC4 distribution.
Figure 3.6: In-situ composition history for butane component during buildup test in
(a) Liquid phase and (b) The overall composition conﬁguration.

0 5 10 15 20 25 30
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
Liquidsaturation(S
c
,fraction)
t = 60 minutes
t = 60.0166 minutes
t = 60.0997 minutes
Figure 3.7: Saturation distribution in the core during buildup.
At and around the producer region the accumulation of the heavier component C4
in the liquid phase can vary from 40% to as high as 75%, and even for the overall
static composition in this region the mole fraction can vary from 30% to 63%. The
different BHP scenarios produce different pressure distributions in the core. The
higher the BHP at the producer, the larger the single-phase region, hence the liquid
accumulates in a smaller region around the well.
Figure 3.9(a) illustrates that the component mole fractions in the flowing phase at
the wellbore do not vary linearly with BHP. When the producer is under the BHP
control of 50 atm, the mole fraction of the heavier component butane in the flowing
phase experiences the greatest lost in the first 40 seconds of flow, and then stabilizes
back to 15% as the flow reaches steady state. However in the BHP = 30 atm case,
instead of losing more butane in the reservoir, there is about 0.43% increase in the
concentration of butane in the produced fluid. This may be due to the fact that part

0 5 10 15 20 25 30
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
xC
4
(liquidC
4
molefractioninthegridblock)
BHP = 30 atm
BHP = 50 atm
BHP = 70 atm
BHP = 90 atm
BHP = 110 atm
0 5 10 15 20 25 30
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
ZC
4
(overallC
4
molefractioninthegridblock)
BHP = 30 atm
BHP = 50 atm
BHP = 70 atm
BHP = 90 atm
BHP = 110 atm
(b) zC4
distribution.
Figure 3.8: In-situ composition history for butane component with diﬀerent BHP
control scenarios in (a) Liquid phase and (b) The overall composition conﬁguration.

3.2. EXPERIMENTAL APPARATUS 37
of the reservoir liquid revaporizes at lower BHP, such as BHP = 30 atm, hence
more butane is produced in the well. When the producer BHP is greater than 50
atm, the higher the BHP, the more butane produced from the well in the first one
minute, then after the first one minute, the butane mole fraction stays at 15%.
Figure 3.9(b) shows the distribution profiles of the liquid saturation at t = 5
minutes for different BHP scenarios. From these profiles, we can conclude that the
lower the bottom-hole pressure at the producer, the shorter the range of the liquid
accumulation in the near-well region. Contrary to the overall and liquid composition
distribution in Figure 3.8, the lower the BHP, the greater the liquid accumulation in
the well. Away from the well, the liquid accumulation increases slightly or remains
constant in the two-phase region for all BHP controls except BHP = 110 atm.
When BHP = 110 atm, the pressure drop along the core is only 20 atm, and under
pressures greater than 110 atm, the reservoir fluid forms less liquid dropout than
the maximum liquid dropout, hence, at t = 5 minutes, the accumulation rate of the
liquid saturation is greater than liquid flow rate, hence more liquid accumulates in
the wellblock.
The preexperiment numerical simulation gave us a rough idea of how the binary
gas-condensate system performs under a constant pressure drop condition and how
fast the composition and saturation redistributes during a buildup. In the subse-
quent experiments, we used the conditions as learned from the numerical simulations
and investigated the flow behavior of the selected gas-condensate system by physical
observations.
3.2 Experimental Apparatus
The experimental apparatus was modified from an earlier design of Shi et al. (2006).
The experiment system is illustrated in Figure 3.10. This system is comprised of four
subsystems: the gas supply and exhaust system, the core flow system, fluid sampling
and data acquisition system. A photograph of the whole system is shown in Figure
3.11. The details of each component in the four subsystems, the major measuring
techniques associated with composition and saturation measurements are presented

10
−1
10
0
10
1
10
2
10
3
0
0.05
0.1
0.15
0.2
0.25
Time (minutes)
FlowingzC4
molefractioninthegridblock
BHP = 30 atm
BHP = 50 atm
BHP = 70 atm
BHP = 90 atm
BHP = 110 atm
(a) C4 in the flowing phase.
0 5 10 15 20 25 30
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
Liquidsaturation(S
c
,fraction)
BHP = 30 atm
BHP = 50 atm
BHP = 70 atm
BHP = 90 atm
BHP = 110 atm
(b) Saturation distribution.
Figure 3.9: Simulation results for different BHP control scenarios. (a)C4 mole frac-
tion profiles in the flowing phase (b) Saturation distribution in the core.

Figure 3.10: Schematic diagram of the gas-condensate flow system. The confining
pressure is provided by a high pressure water pump and the gas-condensate mixture
is stored in a piston cylinder, which is supported by a high pressure nitrogen cylinder
to maintain the mixture pressure at 2200psi. Pressures along the core are monitored
by the high pressure transducers and fluid samples are collected from the six ports
along the core for composition analysis.
in the following sections.
3.2.1 Gas Supply and Exhaust
The upstream gas mixture is stored in a piston cylinder (HaiAn, China, capacity
4,000 ml, pressure range 0-4641 psi), and the cylinder pressure is controlled by a high
pressure nitrogen cylinder (6000 psi). The downstream gas exhaust was discharged to
a fume hood directly in the constant pressure drop experiment since the total volume
of the exhaust is very small and safe to dilute into the atmosphere. After the buildup

(a) Front view.
(b) Rear view.
Figure 3.11: Images of the experiment apparatus for the gas-condensate ﬂow system.
(a) Front view, the high pressure titanium core holder is in the foreground, this
core holder has six ports along the core to allow for pressure monitoring and ﬂuid
sampling (b) Rear view, the sampling system and the pressure transducers are in the
foreground.

test, the core was discharged into another empty piston cylinder, so that the collected
fluid could be analyzed to determine the total composition.
3.2.2 Core Flow System
The core flow system consists of a titanium core-holder (Shiyi Science and Technology,
model J300-01), which can support a maximum confining pressure 5800 psi), while
maintaining the pore pressure at 5366 psi. A photograph of the core holder is shown
in Figure 3.11(a). The high pressure titanium core holder has six ports along its
length to allow for pressure monitoring and fluid sampling. A homogeneous Berea
sandstone core was selected for this experiment. The core has a length of 25.04 cm
and a diameter of 5.06 cm with an average porosity around 15% and an average ab-
solute permeability about 5 md. The choice of permeability was intentional, as it
was necessary to produce pressure drops of suitable magnitude to create the desired
condensation region during flow.
3.2.3 Fluid Sampling System
One of the unusual aspects of this experiment is the ability to measure the in-place
composition, as well as the usual pressure data along the length of the core. The in-
place composition samples are collected with Tedlar gas sampling bags (SKCwest,
model 232-02) attached to the six sampling ports along the core-holder. In order to
protect the gas samples from being polluted by other gases, the gas sampling bags
are connected to the system in a way such that the bags can be vacuumed before
the experiment. The sampling pressure is regulated by the 25 psi relief valves to
ensure the sampling pressure lower than the pressure limits of the sampling bags.
Collecting the fluid samples directly from the flow system is challenging. Both the
sample size and the sampling duration need to be carefully manipulated. To reduce
the error involved in the sampling process and also to ensure all samples are collected
at roughly the same time, the sampling system is specially designed as shown in
Figure 3.12. A one-meter long stainless steel coil is installed prior to the relief valve
to capture and temporarily store the fluid sample. During the sampling process, we

S
p
(a) (b)
Two-way valve
Three-way valve
To the core
Figure 3.12: Schematic and photograph of the gas sampling system. (a) Schematic
diagram. The fluid sample is first stored in the one-meter long coil, then released to
the sampling bag. (b) Photograph of the sampling system.
first opened the two-valve valve (as depicted in Figure 3.12 (a)) connected to the
pressure port in the core holder and captured the fluid sample in the coil, this sample
could then be released later to the sampling bag. At atmospheric pressure, the one-
meter long coil can store as much as 7.91 cm3
of gas, which is sufficient for one gas
chromatography analysis. Fluid samples coming from the core are usually at high
pressure, hence the volume of the fluid stored in the coil is normally expanded to
larger volume in the sampling bag. By experience, at core pressure higher than 1500
psi, opening the two-way valve in Figure 3.12 (a) for 2 seconds, the amount of fluid
stored in the coil will be ideal for gas chromatographic analysis, while at core pressure
within the range of 1000 psi to 1500 psi, 3 to 5 seconds is required. For fluid pressure
lower than 1000 psi, longer sampling time is needed. The collected gas samples were
sent to an Agilent 6820 series gas chromatograph to analyze the compositions. The
gas chromatograph configuration will be discussed in detail in the next section.

3.2.4 Data Acquisition System
All pressure measurements were electronic and digitized by using a high-speed data ac-
quisition system (DAQ; National Instrument, SCSI-1000 with PCI 6023E A/D board).
In the original design of Shi et al. (2006), the in-place pressures were measured by pres-
sure transducers with different capacities, chosen according to the pressure range and
the requirement of the measurement resolution. The absolute pressures on both up-
stream and downstream were measured with high pressure range 2,000 psi transducers
, and the differential pressures between each pair of sampling ports were measured
with low range 320 psi transducers. Several issues arose from this design. First, the
pressure transducers along the core did not generate reliable differential pressure data
in the earlier experiment due to the escalated zero shifting problems and the depen-
dency of each sampling port on its neighbors; secondly, the low pressure transducers
were prone to damage in case of leaks in the system. Pressure differences between
each pair of sampling ports are small when the flow system is under constant pressure
drop and reaches steady-state flow, and can become very large under nonsteady state
conditions. In the redesigned experiment, we replaced all the low pressure transducers
with high pressure ones and measured the absolute pressure at each sampling port
instead of differential pressure between sampling ports. This removed the pressure
dependency on the neighboring ports and prevented over-pressurizing the transducers
along the core. The absolute inlet and outlet core pressures were also monitored. All
pressure data from the eight transducers were logged by the data acquisition system
for analysis.
3.2.5 Gas Chromatography (GC) System
Chromatography is a separation technique used to separate and analyze a mixture
of compounds which are comprised of individual components. A mixture of various
components enters a chromatography process together with the carrier gas, an inert
gaseous mobile phase, and the different components are flushed through the system
at different rates. These differential rates of migration as the mixture moves over
adsorptive materials provide separation, and the rates are determined by the repeated

A
GC system
A
PPI
A
TCD
Sample out
Sample in
Loop
Valve 1 Valve 2
Column1 Column3
8
7 6 5
4
3
2
1
10
9 6
5
4
3
2
1
Column2
Figure 3.13: Schematic diagram of the valve and column configuration in the GC
(Parakh, 2007).
sorption/desorption activities that take place during the movement of the sample over
the stationary bed. The smaller the affinity a molecule has for the stationary phase,
the shorter the time spent in a column. In Gas Chromatography (GC), the sample is
vaporized and injected onto chromatographic columns and then separated into many
components.
In this study, GC analysis for component composition were performed on the
Agilent 6890N series GC, this GC is equipped with a purged packed inlet and single
filament Thermal Conductivity Detector (TCD). The configuration for the valves and
the columns designed inside the GC chamber are shown in Figure 3.13. This valve
and column configuration was designed originally for permanent gas analysis (Zhou
et al. (2003). Valve 1 in this system is a 10-port valve for automatic gas sampling and
backflush of the precolumn to the detector. Two columns can be associated with the
10-port valve. A 6-port switch valve (Valve 2), with adjustable restrictor, is used to
switch the column in and out of the carrier stream. Column 3 is isolated when Valve
2 is on. The purged packed inlet is interfaced directly to the valve to provide a source
of carrier gas. Since there are only two light hydrocarbon components, methane and
butane, in our gas-condensate system, hence one column (Agilent GasPro, 15m×
0.53 mm× 40 µm) was installed in the position of column 1, column 2 was replaced
directly by a by-pass stainless steel tubing, and column 3 was isolated from the system
by switching valve 2 on. The detailed GC setup is listed in Table 3.1:

Table 3.1: Gas Chromatographic Conditions.
GC Agilent 6820 Gas Chromatograph
Data system ChemStation
EPC Purged packed inlet 200◦
C
(Heater temperature)
EPC Purged packed inlet 22.64psi
(Heater pressure)
Valve temperature 150◦
C
Carrier flow(Helium) 3.2mL/min
Column GS-GasPro (part number: J&W 113-4362)
50◦
C initial, hold for 3.00 minutes;
Oven increase from 50◦
C to 200◦
C at the rate of 25◦
C/min;
then hold at 200◦
C for 3 minutes.
Detector TCD, 250◦
C
Reference flow 30.00mL/min
Make up flow 10.00mL/min
The thermal conductivity detector (TCD) used in this study is a concentration
sensitive detector. It is simple and easy to use and suitable for the analysis of perma-
nent gases, hydrocarbons, and many other gases. The single-filament flow-switching
design eliminates the need for a reference column. Since TCD is based on the principle
of thermal conductivity, it depends upon the composition of the gas. The difference in
thermal conductivity between the column effluent flow (sample components in carrier
gas) and the reference flow of carrier gas alone, produces a voltage signal proportional
to this difference. The signal is proportional to the concentration of the sample com-
ponents. Different components in the sample gas produce different signals due to the
difference of the thermal conductivity between the pair of the sample component and
the carrier gas. Thus gas chromatography is a relative method, so calibration with a

25µV
1500
1250
1000
750
500
250
0
Front detector
2.5 5.0 7.5 10 12.5 15 17.5 min
Figure 3.14: GC curve for a methane and butane mixture. The measurement shows
good signal-to-noise ratio, and the baseline is also very stable.
standard mixture is required for mixtures having components with different thermal
conductivities.
Figure 3.14 shows the chromatogram of a mixture with a volume of 10 ml, the
methane and butane were easily detected at a good signal-to-noise ratio. The baseline
was also very stable.
Because the difference of the thermal conductivity between methane and helium
is smaller than that of butane and helium, the butane peak is prone to be wider and
hence the apparent butane mole percentage is elevated to a higher than true value.
Therefore, the measurement is calibrated with mixtures of fixed methane and butane
percentage. Figure 3.15 shows the calibrated curve for butane. The actual butane
percentage in the following experiment is calculated based on the calibration Eq. 3.6:
zC4 c = 0.0084zC4 m2
+ 0.198zC4 m (3.6)
Where, zC4 c and zC4 m are the calibrated butane mole percentage and measured
butane mole percentage respectively.

y = 0.0084x2
+ 0.198x
R2
= 0.9927
0
10
20
30
40
50
60
70
80
90
100
0 10 20 30 40 50 60 70 80 90 100
GC butane area percentage(%)
Actualbutanepercentage(%)
Figure 3.15: The calibration curve for C4 measurements. The calibrated butane mole
percentage is calculated by: zC4 c = 0.0084zC4 m2
+ 0.198zC4 m.
3.2.6 CT system
An X-ray computed tomography (CT) scanner (GE HiSpeed CT/i) was used in this
study to measure the static saturation in the core. The scanner can also be used to
monitor dynamic experiments, such as core ﬂoods as the two phases develop in the
core. Because the CT number is directly proportional to the density of the object, so
we can observe changes in CT numbers as two phases develop in the core.
Measurements with X-ray CT are subject to image artifacts, such as beam harding,
positioning errors and X-artifacts etc. Special care and treatment are needed to
improve the resolution of CT images. According to Akin and Kovscek (2003), object
shape can lead to artifacts, the cross-sectional geometry of the scanner gantry is
circular and the machine delivers the best images of objects that are also circular and
symmetrical in cross-section. Beam hardening can be reduced by simply moving to

Figure 3.16: Apparatus for x-ray CT scanning.
higher energy X-ray sources. Positioning errors can be minimized by setting the scan
object in a fixed position on the patient table. Figure 3.16 shows a photograph of the
CT setup for this experiment. In this setup, positioning is accomplished electronically
with ± 0.01 mm accuracy. An arc-shaped mounting bracket attaches to the core
holder, the inside of the mounting bracket fits the core holder and holds the core holder
tightly, and the outside the mounting bracket fits the patient table, and eliminates
possible slippage between the core holder and the moving patient table. Thus the
core holder is in a fixed position relative to the table.
By trial and error, the best quality resolution was made by selecting the optimum
machine parameters. Table 3.2 shows the scanner settings used in this study.

3.3. EXPERIMENTAL PROCEDURES 49
Table 3.2: CT scanner settings.
Parameter Setting
Field of View (DFOV) 15 cm
SFOV Ped Head
Image Matrix 512 x 512
Sampling 512
Scan Speed 3 sec
Slice Thickness 3mm
Resolution High
Kv 140
MA 200
The tubing system that connects the sample ports to the valve panel was specially
designed to further reduce the influence of beam hardening. In the early stage of the
experiment, Halar Tubing with 2500 psi pressure rating was adopted, the advantage
of Halar tubing is that it is transparent in the CT scanning, but this type of tubing
tends to become brittle and easy to break in the case of high pressure hydrocarbon
flow, especially when the hydrocarbon flow undergoes phase changes. In the later
stages of the experiment, aluminum tubing was adopted. Aluminum tubing has less
beam hardening effect in the scanning system than stainless steel tubing and can also
sustain high flow pressure without rupturing.
3.3 Experimental Procedures
3.3.1 Gas Mixing
According to the preexperiment simulation, 5.5847 moles butane and 31.6465 moles
methane were required to fill the piston cylinder with size of 3,920 ml at 2000 psi
and give the component mole percentage of 85% methane and 15% butane. Butane is

0
5
10
15
20
25
30
35
40
45
0 5 10 15 20 25 30
Temperature (Degree C)
Pressure(psia)
Butane vapor pressure
Figure 3.17: Butane vapor pressure curve.
usually stored in liquid state with the butane tank pressure around 60 psi. According
to Figure 3.17, at room temperature, butane is in liquid phase as long as the fluid
pressure is above 23 psi. The liquid butane can thus be transferred to an empty piston
cylinder by gravity and small pressure difference between the butane tank and the
piston cylinder. Methane usually is supplied in high pressure cylinders, so methane
can be directly transferred to the piston cylinder by the high pressure difference.
Figure 3.18 shows a schematic of the whole process of mixing the liquid butane
with gaseous methane. Firstly, the piston cylinder was vacuumed from the lower end
as shown in Figure 3.18(a), thus the piston was pulled down to the bottom of the
piston cylinder. At the same time, the tubing connecting to the water pump was also
vacuumed to eliminate the air in the piston and tubing line. Water was then pumped
to the vacuumed cylinder. The water can be delivered to the piston cylinder at a
rate ranging from 0.01 ml/min to 9.9 ml/min. Low to intermediate injection rate

was adopted to minimize the air dissolved in the injection water. The piston cylinder
was positioned horizontally after it was filled with water, and the tubing connecting
the piston cylinder and the water pump was pulled vertically, with water head in the
tubing high above that in the piston cylinder. The water-filled piston cylinder stayed
horizontally for half a day to allow the dissolved air to evolve into the higher end of
the tubing. The next step was to open the valve at the higher tubing end, and release
all the accumulated air in the tubing, then put the piston cylinder back to vertical.
Then the higher end of the tubing was opened again, still at a position higher than
the top water level in the piston cylinder. Water was injected and the piston cylinder
was ready for the next step if no water flowed spontaneously out of the cylinder. The
water can flow out of the piston cylinder spontaneously only if the pressure inside
the water-filled piston cylinder is higher than the atmospheric pressure. In this case,
the cylinder is either pumped with too much water or there is too much air dissolved
in the cylinder. Both scenarios are undesirable and would definitely influence the
butane transfer in the next step, hence the water injection needs to be done carefully.
Secondly, the space was prepared for butane transfer. The volume of 5.6 moles
liquid butane at room temperature is equal to a volume of 539 ml water. To transfer
5.6 moles liquid butane to the piston cylinder, we first injected nitrogen into the top
of the water-filled piston cylinder prepared in Figure 3.18(a), so that the nitrogen
drove the piston down and expelled the water out from the bottom. The next step
was to open the valve at the bottom of the piston cylinder slowly, and collect the
water in a beaker and weigh the water on a digital scale, shutting down the valve
when the displaced water read 539 g. Then the nitrogen was released from the top of
the piston cylinder, and the nitrogen source disconnected from the system.
Thirdly, the butane cylinder was connected to the the piston cylinder prepared in
Figure 3.18(b) and then the tubing connection part and the top of the piston cylinder
were vacuumed. If no air was dissolved in the water in the first step, then the piston
will not be pulled up by the vacuum pressure since water has very low compressibility
at room temperature. The butane cylinder was put upside down such that the liquid
butane can flow directly into the piston cylinder. The butane was transferred and
settled in the piston cylinder in a few minutes. The practice was to wait about half

an hour until the pressure in the butane cylinder stopped dropping. Then the valve
on the butane cylinder and the valve on the top of the piston cylinder were shut, as
in Figure 3.18(c). 5.6 moles butane had therefore been successfully transferred into
the piston cylinder.
Lastly, the butane cylinder was disconnected, and the methane cylinder connected
to the piston cylinder partially filled with butane as in Figure 3.18(c). The next step
was to vacuum the connecting tubing and flow the methane directly into the piston
cylinder as in Figure 3.18(c) and discharge all the remaining water from the bottom
of the piston cylinder to the water bottle. The amount of methane transferred to the
piston cylinder depends on the pressure on the methane cylinder. When the maximum
pressure of the methane supply cylinder is around 2100 psi, the methane transferred
to the piston cylinder is roughly 32 moles and the equilibrium pressure in the piston
cylinder is about 2000 psi. Hence the mole percentage of the methane in the mixture
is about 85%. Varying the supply pressure on the methane cylinder, we were able to
slightly adjust the composition for the mixture by flowing less or more methane into
the piston cylinder. The final composition of the mixture was determined accurately
by GC composition analysis prior to conducting the flow experiment
The mixture prepared in Figure 3.18 (d) was ready for use when the piston cylinder
was shaken 100 times to allow the methane and butane to be fully mixed with each
other, then the mixture was pressurized to 2,200 psi for the core flow experiment by
connecting the lower (empty) end to the high pressure nitrogen supply.
3.3.2 Core Flow Tests
In this section, the procedure of the five core flow experiments will be explained in
detail. In Experiments A and B, the core was vacuumed and the hydrocarbon mixture
was injected directly into the core before the flow experiment, while in Experiments
C and D, the core was vacuumed and presaturated with high pressure methane.
Experiment C and D were “capture” experiments in which the fluid flowed in the
core for a given time, then both inlet and outlet valves were suddenly shut and all
six sample parts immediately opened to sample the composition of the fluids. Fluid

Figure 3.18: Overview of the gas mixing process. (a) Vacuum and fill the piston
cylinder with water (b) Displace water from the piston cylinder with specified volume
(c) Discharge liquid butane into the piston cylinder (d) infill the piston cylinder with
high pressure methane.

samples were collected immediately after the core was captured. In Experiment E,
the apparent permeabilities of the core to nitrogen gas were measured before and also
after the hydrocarbon flow test.
Experiment A
In Experiment A, the whole flow system, including the core, the sampling system
and the gas supply system, was fully vacuumed. The mixture in the piston cylinder
was pressurized to 2200 psi with the support of the high pressure nitrogen. The
maximum pressure of the nitrogen cylinder was 6000 psi and nitrogen was delivered
under a pressure of 2200 psi using a regulator. The high pressure support from the
nitrogen ensures the hydrocarbon mixture is always delivered as single-gas phase, as
2200 psi is well above the dewpoint of 1900 psi. During the experiment, the pressure
regulator at the upstream was set around 1950 psi, the downstream valve was closed.
The high pressure gas phase mixture was first flowed into the vacuumed core, and
settled for about 2 minutes until the pressure in the core reached 1950 psi, then the
first batch of fluid samples was taken.
The second batch of samples were taken during flow, which was controlled to
be constant pressure drop with the upstream pressure regulator set at 1950 psi and
downstream back pressure regulator set at 1000 psi. Samples were taken 40 seconds
after the pressure drop along the core was stabilized. In this experiment, the coil
setup shown in Figure 3.12 was originally a stainless tubing about 20 cm long. Longer
sampling time was found necessary to ensure a sufficient sample size. The straight
short tubing was later replaced by the 1 meter long coil in Experiments C, D and
E to increase the sample volume. Because of the extended sampling time, there was
sudden and dramatic pressure drop in the core during each sampling process.
Experiment B
Similar to Experiment A, two batches of samples were collected during the static
and flowing conditions. Different from Experiment A, the mixture in Experiment B
was slightly lighter because of the lower pressure provided by the methane cylinder

during the mixing process. The upstream pressure was regulated to a higher pressure
of 2000 psi, hence the static samples were taken at 2000 psi. During the flowing
stage, the upstream pressure was regulated to 2000 psi, and downstream to 500 psi,
hence a bigger pressure drop occurred during Experiment B. In addition to changes
in the pressure setting, the sampling was manipulated with extreme care during
the experiment, and the two-way valves in Figure 3.12(a) were turned on slowly
to minimize the sudden pressure drop during sampling.
After the flow, we shut down both the upstream and downstream valves on the
core, as well as the valves on the sampling ports. The core was isolated, detached
and taken to the CT scanning room for saturation analysis.
Experiment C
After Experiment B, the longer sampling coil design as in Figure 3.12 was adopted
for better sampling. During the experiment, the core was vacuumed and presaturated
with pure methane at a pressure around 2000 psi. Then at least two pore volumes of
the gas mixture of methane and butane were flushed through the core to fully displace
original methane gas. During the displacement process, the upstream pressure was
set around 2000 psi and downstream to 1950 psi to ensure the mixture of methane
and butane in the core was still in the gas phase. After about 10 minutes of the low
pressure-drop flow, the downstream pressure was set at 1000 psi. Flow occurred at a
high constant pressure drop for 3 minutes and reached steady state, then four valves,
one before the upstream pressure regulator, one prior to the core holder, one right
after the core holder and the one in the downstream of the back pressure regulator
were all shut, capturing the flowing gas within the core. Samples from the six sample
ports along the core were collected immediately after the flow shutoff. One sample
from the tubing upstream of the core was collected, as well as a sample from the
tubing between the back pressure regulator and the outlet end of the core. The valve
at the end of the core was then opened, the fluid in the core was fully discharged into
an empty piston cylinder, and one sample from the exhaust was collected.

Experiment D
The first part of Experiment D was exactly the same as in Experiment C, except
the mixture was heavier than that in Experiment C. The heavier fluid was chosen
to investigate the influence of the original fluid property on compositional variation.
After discharging the hydrocarbon gas into the collection piston cylinder, the remain-
ing liquid in the core was flushed out by injecting nitrogen into the core and three
samples at the exit of the core were taken at three different times.
Experiment E
The apparent permeability to nitrogen was measured before and after the hydrocarbon
flow test. The nitrogen was injected into the core with different pressures and the
downstream flow rates were measured using the upside-down cylinder method, in
which the volume of the gas outflow during a fixed time duration was calculated by
monitoring the water displaced from the upside down glass graduated cylinder.
3.3.3 Sampling from the Tubing Ports
Earlier experience showed that samples from the various tubing ports were often prob-
lematic, and displayed different compositions when sampled under different pressure.
This phenomena was more severe when the sampling pressure was below the dewpoint
pressure. This was attributed to the fact that liquid and gas phases flow at different
rate inside the tubing, hence the fluid captured in the sampling bag preferentially
carried more gas or liquid, depending on whether the tube was pointing upward or
downward. Hence the sample from the tubing was not representative. To reduce the
sampling bias, heat tape was attached around the tubing as shown in Figure 3.19,
to shift the fluid phase behavior to single-phase gas at a higher temperature. This
approach showed a considerable improvement, as shown in Figure 3.20.

Gas condensation process

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